The present invention relates to a composition and method for enhancing the recovery of petroleum from an oil-bearing formation.
In the recovery of oil from reservoirs, the use of primary production techniques (i.e., the use of only the initial reservoir pressure to recover the crude oil) followed by the secondary recovery technique of waterflooding, recovers only a portion of the original oil present in the formation. Moreover, the use of certain tertiary enhanced oil recovery (EOR) techniques is also known in the art. These tertiary recovery techniques involve injection of any suitably tailored composition of fluids for e.g., water with tailored salinity, re-injection of hydrocarbon gases produced from the formation, injection of gases like CO2, nitrogen, air, or in cases of heavy oil thermal methods can be used by increasing the enthalpy of injected fluid e.g., utilizing steam, and injection of chemicals like surfactants and polymers to enhance performance of any of these recovery techniques.
A typical procedure that has been implemented over several decades involve cyclic injections of alternating slugs of high viscosity fluids such as water followed by a slug of gas such as CO2, for example, the discussion in U.S. Pat. No. 2,623,596. Moreover, U.S. Pat. No. 3,065,790 indicates that this process may be more cost effectively employed if the slug of CO2 is relatively small. In fact, as illustrated by U.S. Pat. No. 3,529,668, this type of recovery procedure is typically performed in “water alternating gas (WAG)” cycles. However WAG strategy is effective only in the initial stages of gas flooding. Volumetric sweep inefficiencies arise, typically as a result of viscous fingering, reservoir heterogeneity and gravity segregation. Due to its low viscosity, gases like CO2 establish a preferentially connected pathway and sweeps mostly through high permeability zones in a reservoir with heterogeneous permeability distribution. Gravity segregation occurs when gas due to its low density, segregates from the water front and preferentially sweeps the top section of a reservoir. A substantial volume of upswept oil is bypassed as a result of these effects.
One proposed solution to this problem associated with the channeling of the gas bypassing the oil, is the injection of water which contains a surfactant alternating or co-injecting with the gas. The process is referred to as foam EOR. In particular, surfactants have been proposed as a means for generating a foam or an emulsion in the formation. See, for example, U.S. Pat. Nos. 4,380,266; 4,860,828; and 5,502,538. The purpose of this foam is to divert the flow of the CO2 into that portion of the formation containing high oil saturation.
The surfactants used in foam EOR processes, however, have suffered from a number of drawbacks. It has been shown that adsorption of surfactants accounts for one of the major losses of the surfactant. Excessive adsorption hampers the transport of surfactant into far field and thus its availability to form foam deep into the reservoir. Anionic surfactants adsorb heavily on carbonate rocks while nonionic surfactants adsorb on sandstone rocks. Furthermore, the surfactant must be stable in the formation brine and should not form a separate misceller phase which may limit the transport of the surfactant in the reservoir.
Many prior art surfactants for example, alpha-olefin sulphonate surfactants, largely known as “good foamers”, are known to suffer from numerous stability issues, for example solubility issues in some brine solutions as well as instability of the surfactant stabilized foam in the presence of oil especially at higher temperatures. More specifically, for CO2 flooding process it has been shown that the most efficient method of transport and implementation of foam EOR process happens if the surfactants partitions and gets transported along with the CO2 phase. While some conventional anionic surfactants, such as alpha-olefin sulphonates, adsorb less on sandstone and can form foams at certain reservoir conditions, they cannot be transported along with CO2. Nonionic surfactants can be transported through the CO2 phase but they have excessive adsorption on sandstones, adversely affecting the feasibility of the foam EOR implementation.
There remains a need for suitable foam-forming composition, especially sandstone formations, comprising foaming agents which will allow enhanced oil recovery in an efficient manner. In particular, there is a need for suitable foam-forming composition comprising foaming agents which have a reduced tendency to adsorb in rock formations, with ability of active foaming components that can be transported through CO2, demonstrate improved brine and temperature tolerance and enhanced stability in presence of crude oil.